Fracturing is a process that can be used during well completion in an effort to enhance oil-and-gas production. Fracturing occurs by producing high pressures within a geological formation that contains a hydrocarbon-bearing reservoir. The high pressures physically fracture and crack the formation to provide or improve fluid communication between the reservoir and a well.
Sliding sleeves are a known completion component that can be run into a well. Sliding sleeves typically have radial ports that allow fluid flow between an internal space of tubing or casing and the local environment that surrounds the well. Ball-actuated sliding sleeves can be positioned in a well in a closed configuration. The ball-actuated sliding sleeves can be actuated by dropping a ball of specific size into the well and pumping it with well fluids until it seats on an appropriately sized ball-seat. Continued fluid pressure pushed against the seated ball and moves the sliding sleeve into an open configuration. In the open configuration fluid ports are exposed, which provides fluid communication between the internal space of the tubing or casing and the local environment that surrounds the well. The fluid communication allows a specific region of the geological formation and the hydrocarbon-bearing reservoir to be exposed to a high-pressure fluid from the well, which can create a fracture stimulation. Simulating a specific region of the geological formation and the hydrocarbon-bearing reservoir allows the stimulation operation to be configured to variations in local conditions.
Progressive access to different stages of the reservoir can be achieved by using balls and ball-receiving seats of progressively increasing diameters from a distal end of the well towards a surface end of the well. Small diameter balls and corresponding small ball seats have a small flow channel which can restrict flow rate or can produce an excessive pressure drop. Small components are also susceptible to erosion causing premature failure. These considerations give a lower limit to the size of the smallest ball that can practically be used in a ball-drop fracturing operation. For example, under conditions within a typical oil-well the smallest ball may be no smaller than about 0.750 inches in diameter (one inch is equivalent to about 0.0254 metres). The maximum diameter for the largest ball is limited because it must fit and be free to move within the smallest diameter of the well, within either a well liner or a casing. For example, a typical oil-well casing-string has about a 4.5 inch outer diameter (OD), an inner diameter (ID) of about 4 inches and a drift diameter is of about 3.875 inches. This typically limits the maximum diameter of a largest ball to about 3.813 inches.
The difference in diameter between successive balls must be such that a given ball can pass through the ball-receiving seat that is sized for the next largest ball.
During fracturing operations, the ball and ball-receiving seat must withstand a large hydraulic pressure. For example a hydraulic pressure in excess of 10,000 pounds per square inch (psi, one psi is equivalent to about 6.89 kilo-Pascals). Typically ball-receiving seats have a significant overlap of material to support the ball during a pressure loading phase of the fracturing operation. For example, the ball-receiving seat may have an ID which is about 0.240 inches smaller than the outside diameter of the ball. However, even when using durable materials, such as ductile iron, balls and seats can plastically deform or physically break apart under high hydraulic pressures, which causes the functional seal formed by the ball and seat to be lost.
A known approach for addressing the dimensional limitations of ball and ball-receiving seat systems is to use malleable balls or dissolvable balls. Malleable balls may be introduced into a well and become seated in a downhole ball-receiving seat to form a ball-seat unit. The ball-seat unit may then be moved by pressurized fluids within the wellbore to move the ball-seat unit to an actuated position which may facilitate a treatment of the hydrocarbon-bearing reservoir. While in the actuated position, the pressurized fluids, or higher pressure fluids, may deform the ball within the ball-seat unit. The deformed ball can then move through the ball-receiving seat, which disassembles the ball-seat unit. Alternatively, dissolvable balls can introduced into a well and become seated in a downhole ball-receiving seat to form a dissolvable ball-seat unit. The dissolvable ball-seat units can also be moved by pressurized fluid to an actuated position. While in the well, the dissolvable balls can dissolve in the presence of well fluids. Typically when the dissolvable ball-seat unit achieves the actuated position, the ball will dissolve enough to allow the ball to pass through the ball-receiving seat, which disassembles the dissolvable ball-seat unit. Disassembly of the ball-seat units or the dissolvable ball-seat units may be required by an operator to restore fluid communication across the ball-seat unit.
Malleable balls, composite balls, and dissolvable balls are known to physically break up or plastically deform when they contact the ball-receiving seat. These broken balls are not able to form a moveable unit with the ball-receiving seat and may require the use of further balls. Furthermore, when high hydraulic pressures are applied to the moveable unit, the seat itself may deform and the intended seal with the ball is lost.